US4659453A - Hydrovisbreaking of oils - Google Patents
Hydrovisbreaking of oils Download PDFInfo
- Publication number
- US4659453A US4659453A US06/826,406 US82640686A US4659453A US 4659453 A US4659453 A US 4659453A US 82640686 A US82640686 A US 82640686A US 4659453 A US4659453 A US 4659453A
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- molybdenum
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
- C10G47/24—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles
- C10G47/26—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles suspended in the oil, e.g. slurries
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
- C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
- C10G45/14—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing with moving solid particles
- C10G45/16—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing with moving solid particles suspended in the oil, e.g. slurries
Definitions
- this invention relates to a process for hydrovisbreaking liquid hydrocarbon-containing feed streams so as to produce lower boiling hydrocarbons.
- this invention relates to the use of a new inorganic molybdenum and sulfur containing catalyst composition in a hydrovisbreaking process so as to minimize coke formation.
- hydrotreat hydrofine liquid hydrocarbon-containing feed streams such as heavy oils, which contain undesirable metal and sulfur compounds as impurities and also considerable amounts of cokable materials (referred to as Ramsbottom carbon residue), so as to convert them to lower boiling materials having lower molecular weight than the feed hydrocarbons and to remove at least a portion of metal and sulfur impurities and cokable materials.
- a specific type of hydrotreating process is heat-soaking, preferably with agitation, in the presence of hydrogen but preferably in the absence of a fixed catalyst bed, hereinafter referred to as hydrovisbreaking.
- a process for hydrotreating hydrocarbon feed streams comprises the step of contacting
- (b) is (NH 4 ) 2 S and (c) is MoO 3 .
- the atomic S:Mo ratio in the catalyst composition (C) is in the range of from about 0.8:1 to about 2.3:1.
- the contacting of the hydrocarbon feed streams with the hydrogen-containing gas and the catalyst composition is carried out by heating with agitation, in the substantial absence of a solid hydrofining catalyst.
- the preferred hydrocarbon feed stream has more than about 1 weight-% Ramsbottom carbon residue.
- substantially liquid catalyst composition (C) in the hydrotreating process of this invention results in less coke formation than hydrotreating with no additive or with molybdenum catalyst compositions prepared at S:Mo atomic ratios outside the range of this invention.
- FIG. 1 shows a graphic correlation between coke formation in a hydrovisbreaking process and the atomic S:Mo ratio in a catalyst composition employed in said process.
- Any hydrocarbon-containing feed stream that is substantially liquid at the contacting conditions of the process of this invention and contains Ramsbottom carbon residue in excess of about 0.1 weight-% (determined according to ASTM D-524) can be processed using the above-described catalyst composition in accordance with the present invention.
- Suitable hydrocarbon-containing feed streams include crude oil, petroleum products, coal pyrolyzates, products from extraction and/or liquefaction of coal and lignite, products from tar sands, shale oil, products from shale oil and similar products.
- Preferred hydrocarbon feed streams include full range (untopped) crudes, topped crudes having a boiling range in excess of about 343° C. and residua.
- the present invention is particularly directed to heavy feed streams such as heavy full range crudes, heavy topped crudes and residua and other materials which are generally regarded as too heavy to be distilled. These materials will generally contain the highest concentrations of Ramsbottom carbon residue, metals (Ni, V), sulfur and nitrogen.
- the Ramsbottom carbon residue content of the hydrocarbon feed stream exceeds about 1 weight-% and more preferably is in the range of about 2-30 weight-%.
- the hydrocarbon-containing feed steam also contains about 3-500 ppmw nickel (parts by weight of Ni per million parts by weight of feed), about 5-1000 ppmw vanadium, about 0.2-6 weight-% sulfur, about 0.1-3 weight-% nitrogen and 1-99 weight-% of materials boiling in excess of about 1000° F. under atmospheric pressure conditions.
- the API 60 gravity of the feed is in the range of from about 4 to about 30.
- the free hydrogen containing gas used in the hydrotreating process of this invention can be substantially pure hydrogen gas, or can be mixtures of hydrogen with other gases such as nitrogen, helium, methane, ethane, carbon monoxide or hydrogen sulfide. At present, substantially pure hydrogen gas is preferred.
- the catalyst composition (C) employed in the process of this invention can be prepared in any manner and in any apparatus which affords mixing of (a) water, (b) at least one alkali metal sulfide or ammonium sulfide or at least one alkali metal hydrogen sulfide or ammonium hydrogen sulfide or mixtures thereof, and (c) at least one compound that contains chemically bound Mo and O, in any order and in such amounts that a substantially clear solution is obtained and the S:Mo atomic ratio in the catalyst composition is in the range of from about 0.6:1 to about 3.0:1, preferably from about 0.8:1 to about 2.3:1.
- the amount of water in the substantially liquid catalyst composition (C) is in the range of from about 85 to about 98 weight percent, preferably from about 90 to about 95 weight percent.
- the mixing is carried out with agitation at room temperature. It is believed that at least a portion of ingredients (b) and (c) are converted to thiomolybdates wherein at least a portion of oxygen in (c) is replaced by sulfur. Even though it is preferred to make a clear solution, it is within the scope of this invention to obtain a solution having small amounts of solid particles dispersed therein.
- the solution plus dispersed particles can be used as is in the hydrotreating process of this invention; or the dispersed solid particles can be separated from the solution by any suitable separation technique such as filtration, centrifugation, or settling and subsequent draining.
- the presently preferred sulfide (b) is (NH 4 ) 2 S, which may be in a hydrated form.
- Molybdenum and oxygen containing compounds that can be employed as reagent (c) in the preparation of catalyst composition (C) include molybdenum oxides, molybdenum blue, molybdic acids, ammonium and alkali metal orthomolybdates, ammonium and alkali metal dimolybdates, ammonium and alkali metal heptamolybdates, ammonium and alkaki metal isomolybdates, phosphomolybdic acid and ammonium salts thereof, and the like, and mixtures thereof.
- MoO 3 which may contain some chemically bound water.
- any suitable quantity of the free hydrogen containing gas can be employed in the process of this invention.
- the quantity of hydrogen gas used to contact the hydrocarbon-containing feedstock, either in a continuous or in a batch process, will generally be in the range of about 100 to about 20,000 standard cubic feet (SCF) H 2 per barrel of the hydrocarbon-containing feed and will more preferably by in the range of about 500 to about 5,000 standard cubic feet H 2 per barrel of the hydrocarbon-containing feed stream.
- any suitable amount of the substantially liquid catalyst composition (C) can be employed.
- the amount of the catalyst composition to the hydrocarbon feed will generally be such as to provide a concentration of about 1-2000, more preferably about 5-500 ppmw, of molybdenum (calculated as element) in the feed stream.
- the hydrotreating process of this invention can be carried out by means of any suitable apparatus whereby there is achieved an intimate contact of the hydrocarbon-containing feed stream, the free hydrogen-containing gas and the substantially liquid Mo-S-containing catalyst composition (C), under such hydrotreating (hydrovisbreaking) conditions as to produce a liquid hydrocarbon-containing product having lower Ramsbottom carbon residue than the feed stream.
- this hydrovisbreaking process also reduces the amount of undesirable materials boiling in excess of 1000° F. (at 1 atm) and the amounts of nickel, vanadium, sulfur and nitrogen compounds contained as impurities in the hydrocarbon-containing feed stream.
- the hydrovisbreaking process can be carried out as a continuous process or as a batch process.
- feed stream refers to both continuous and batch process.
- the hydrocarbon feed stream In a continuous operation, it is preferred to premix the hydrocarbon feed stream with the liquid catalyst composition, e.g., in a vessel equipped with a mechanical stirrer, or in a static mixer, or by means of a recirculating pump.
- This mixture of (A) and (C) is then passed concurrently with a stream of free hydrogen-containing gas into the bottom portion of a reactor, which is preferably equipped with heating means and also mechanical agitating or static mixing means so as to provide intimate contact of the process ingredients (A), (B) and (C) at elevated temperatures.
- the products generally exit through outlets located in the top portion of the reactor.
- (A) and (C) can also be premixed and charged to a reactor equipped with heating means and agitating a static mixing means.
- the reactor is then generally pressured with hydrogen gas.
- process ingredients (A), (B) and (C) simultaneously, or sequentially in any order, to the reactor.
- solid materials either umpromoted refractory oxides or phosphates (e.g., Al 2 O 3 , SiO 2 , AlPO 4 and the like) or promoted hydrofining catalysts (e.g., Ni/Mo/Al 2 O 3 or Co/Mo/Al 2 O 3 ).
- umpromoted refractory oxides or phosphates e.g., Al 2 O 3 , SiO 2 , AlPO 4 and the like
- promoted hydrofining catalysts e.g., Ni/Mo/Al 2 O 3 or Co/Mo/Al 2 O 3 .
- reaction time i.e., the time of contact between (A), (B) and (C)
- the reaction time will range from about 0.01 hours to about 20 hours.
- the reaction time will range from about 0.1 to about 5 hours and more preferably from about 0.25 to about 3 hours.
- the flow rate of the hydrocarbon containing feed stream should be such that the time required for the passage of the mixture through the reactor (residence time) will preferably be in the range of about 0.1 to about 5 hours and more preferably about 0.25 to about 3 hours.
- the hydrocarbon containing feed stream will preferably remain in the reactor for a time in the range of about 0.1 hours to about 5 hours and more preferably from about 0.25 hours to about 3 hours.
- the hydrovisbreaking process of this invention can be carried out at any suitable temperature.
- the temperature will generally be in the range of about 250° C. to about 550° C. and will preferably be in the range of about 380° to about 480° C. Higher temperatures do improve the removal of impurities but such temperatures may have adverse effects on coke formation. Also, economic consideration will have to be taken into consideration in the selection of the reaction temperature.
- reaction pressure will generally be in the range of about atmospheric (0 psig) to about 10,000 psig. Preferably, the pressure will be in the range of about 500 to about 3,000 psig. Higher hydrogen pressures tend to reduce coke formation but operation at high pressure may have adverse economic consequences.
- the gaseous, liquid and solid products of the hydrofining (hydrovisbreaking) process of this invention can be withdrawn from the contacting reactor and separated from each other by any conventional separating means. Also, the fractionation of the liquid hydrocarbon product having reduced Ramsbottom carbon residue into fractions boiling in different temperature ranges can be carried out by any conventional distillation means, either under atmospheric or vacuum conditions.
- At least a portion of the liquid hydrocarbon-containing effluent from the hydrovisbreaking reactor is first treated in at least one additional hydrotreating process, more preferably carried out in a fixed bed reactor containing a suitable solid hydrofining catalysts (such as Co/Mo/Al 2 O 3 or Ni/Mo/Al 2 O 3 ) so as to reduce the amounts of remaining impurities (Ni, V, S, N, coke precursors) in the liquid, and is then treated in a catalytic cracking process (e.g., a FCC process employing clay- or zeolite-containing catalysts) under such conditions so as to produce gasoline, distillate fuels and other useful products.
- a catalytic cracking process e.g., a FCC process employing clay- or zeolite-containing catalysts
- the unit After heating at about 800° F. for about 60 minutes, the unit was cooled as quickly as possible, depressured and opened. The liquid product was collected and analyzed. Primarily, the amount of dispersed coke particles (collected by filtration through a 0.45 ⁇ m membrane filter and weighing) and the amount of the fraction boiling above 1000° F. was determined.
- This example illustrates the preparation of a liquid molybdenum and sulfur-containing catalyst composition within the scope of this invention.
- An aqueous solution containing 42.1 weight-% (NH 4 ) 2 S (provided by Chemical Products Corporation, Carterville, Ga.) was filtered so as to remove suspended dark particles.
- the filtered liquid had a yellow color of less than 1.5 (determined by ASTM D-1500).
- Example 1 illustrates the results of hydrovisbreaking tests in accordance with the procedure outlined in Example I employing the liquid Mo-S-containing catalyst compositions described in Example II. Also tested in control runs were MoO 3 and MoS 2 . Test results are summarized in Table 1.
- FIG. 1 The test results are illustrated in FIG. 1, in which coke formation is plotted versus Mo:S atomic ratio.
- the graph in FIG. 1 clearly shows that coke formation was acceptably low (4 wt-% or less at the test conditions) only when the S:Mo atomic ratio of the liquid catalyst composition of this invention (prepared from (NH 4 ) 2 S, MoO 3 and H 2 O) was in the range of from about 0.6 to about 3.0.
- the preferred Mo:S atomic range was about 0.8-2.3 (resulting in coke formation of 3 weight-% or less at the test conditions).
- MoS 2 was not a suitable catalyst (in spite of its 2:1 atomic ratio of Mo to S) because it caused excessive cracking and gas formation.
Abstract
Description
TABLE I __________________________________________________________________________Run 1 2 3 4 5 6 7 (Control) (Control) (Invention) (Invention) (Control) (Control) (Control) __________________________________________________________________________ Catalyst MoO.sub.3 (NH.sub.4).sub.2 S + (NH.sub.4).sub.2 S + (NH.sub.4).sub.2 S + (NH.sub.4).sub.2 S + (NH.sub.4).sub.2 S MoS.sub.2 MoO.sub.3 MoO.sub.3 MoO.sub.3 MoO.sub.3 MoO.sub.3 S:Mo Atomic Ratio 0:1 0.5:1 1:1 2:1 4:1 6:1 2:1 ppm Mo Added to Feed 100 100 100 100 100 100 100 Coke Formation 10.6 4.5 2.1 2.7 5.7 --.sup.2 --.sup.2 (Wt. % of Feed 1000° F. + Conversion 75.2 --.sup.3 61.3 67.1 71.7 --.sup.2 --.sup.2 (Wt. %) __________________________________________________________________________ .sup.1 average of 4 runs .sup.2 test could not be completed due to overpressure (caused by excessive cracking and generation of gases) .sup.3 not measured .sup.4 Note: When a slurry of MoO.sub.3 and NH.sub.3 (mole ratio: 1:0.5) was used in lieu of MoO.sub.3 in a test similar to run 1, coke formation was 9.1 (wt. % of feed).
Claims (17)
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US06/826,406 US4659453A (en) | 1986-02-05 | 1986-02-05 | Hydrovisbreaking of oils |
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US06/826,406 US4659453A (en) | 1986-02-05 | 1986-02-05 | Hydrovisbreaking of oils |
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US4659453A true US4659453A (en) | 1987-04-21 |
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US06/826,406 Expired - Lifetime US4659453A (en) | 1986-02-05 | 1986-02-05 | Hydrovisbreaking of oils |
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Cited By (23)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4814065A (en) * | 1987-09-25 | 1989-03-21 | Mobil Oil Company | Accelerated cracking of residual oils and hydrogen donation utilizing ammonium sulfide catalysts |
EP0343045A1 (en) * | 1988-05-19 | 1989-11-23 | Institut Français du Pétrole | Catalytic composition comprising a metal sulfide suspended in an asphaltene containing liquid and hydrocarbon feed hydroviscoreduction process |
FR2631631A1 (en) * | 1988-05-19 | 1989-11-24 | Inst Francais Du Petrole | Process for hydrovisbreaking of a hydrocarbon feedstock in the presence of a catalyst composition comprising a metal sulphide in suspension in a liquid containing asphaltenes |
US5080777A (en) * | 1990-04-30 | 1992-01-14 | Phillips Petroleum Company | Refining of heavy slurry oil fractions |
US5954950A (en) * | 1995-09-07 | 1999-09-21 | Institut Francais Du Petrole | Intensive hydrofining of petroleum fractions |
US20030139299A1 (en) * | 2001-12-17 | 2003-07-24 | Exxonmobil Upstream Research Company | Solids-stabilized oil-in-water emulsion and a method for preparing same |
US20040014821A1 (en) * | 2002-05-02 | 2004-01-22 | Ramesh Varadaraj | Oil-in-water-in-oil emulsion |
US20040122111A1 (en) * | 2000-04-25 | 2004-06-24 | Ramesh Varadaraj | Stability enhanced water-in-oil emulsion and method for using same |
US6800193B2 (en) | 2000-04-25 | 2004-10-05 | Exxonmobil Upstream Research Company | Mineral acid enhanced thermal treatment for viscosity reduction of oils (ECB-0002) |
US20040256292A1 (en) * | 2003-05-16 | 2004-12-23 | Michael Siskin | Delayed coking process for producing free-flowing coke using a substantially metals-free additive |
US20050258070A1 (en) * | 2004-05-14 | 2005-11-24 | Ramesh Varadaraj | Fouling inhibition of thermal treatment of heavy oils |
US20050258075A1 (en) * | 2004-05-14 | 2005-11-24 | Ramesh Varadaraj | Viscoelastic upgrading of heavy oil by altering its elastic modulus |
US20050263440A1 (en) * | 2003-05-16 | 2005-12-01 | Ramesh Varadaraj | Delayed coking process for producing free-flowing coke using polymeric additives |
US20050269247A1 (en) * | 2004-05-14 | 2005-12-08 | Sparks Steven W | Production and removal of free-flowing coke from delayed coker drum |
US20050279673A1 (en) * | 2003-05-16 | 2005-12-22 | Eppig Christopher P | Delayed coking process for producing free-flowing coke using an overbased metal detergent additive |
US20050279672A1 (en) * | 2003-05-16 | 2005-12-22 | Ramesh Varadaraj | Delayed coking process for producing free-flowing coke using low molecular weight aromatic additives |
US20050284798A1 (en) * | 2004-05-14 | 2005-12-29 | Eppig Christopher P | Blending of resid feedstocks to produce a coke that is easier to remove from a coker drum |
US20060006101A1 (en) * | 2004-05-14 | 2006-01-12 | Eppig Christopher P | Production of substantially free-flowing coke from a deeper cut of vacuum resid in delayed coking |
US20060110310A1 (en) * | 2004-11-19 | 2006-05-25 | Tomco2 Equipment Company | Systems and methods for reducing carbonates in a chlorination system |
US20090184029A1 (en) * | 2008-01-22 | 2009-07-23 | Exxonmobil Research And Engineering Company | Method to alter coke morphology using metal salts of aromatic sulfonic acids and/or polysulfonic acids |
US20090200204A1 (en) * | 2004-09-10 | 2009-08-13 | Chevron U.S.A. Inc. | Hydroprocessing Bulk Catalyst and Uses Thereof |
US20100234212A1 (en) * | 2004-09-10 | 2010-09-16 | Axel Brait | Hydroprocessing bulk catalyst and uses thereof |
US8100178B2 (en) | 2005-12-22 | 2012-01-24 | Exxonmobil Upstream Research Company | Method of oil recovery using a foamy oil-external emulsion |
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Cited By (54)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4814065A (en) * | 1987-09-25 | 1989-03-21 | Mobil Oil Company | Accelerated cracking of residual oils and hydrogen donation utilizing ammonium sulfide catalysts |
EP0343045A1 (en) * | 1988-05-19 | 1989-11-23 | Institut Français du Pétrole | Catalytic composition comprising a metal sulfide suspended in an asphaltene containing liquid and hydrocarbon feed hydroviscoreduction process |
FR2631631A1 (en) * | 1988-05-19 | 1989-11-24 | Inst Francais Du Petrole | Process for hydrovisbreaking of a hydrocarbon feedstock in the presence of a catalyst composition comprising a metal sulphide in suspension in a liquid containing asphaltenes |
US5080777A (en) * | 1990-04-30 | 1992-01-14 | Phillips Petroleum Company | Refining of heavy slurry oil fractions |
US5954950A (en) * | 1995-09-07 | 1999-09-21 | Institut Francais Du Petrole | Intensive hydrofining of petroleum fractions |
US7186673B2 (en) | 2000-04-25 | 2007-03-06 | Exxonmobil Upstream Research Company | Stability enhanced water-in-oil emulsion and method for using same |
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